Not Applicable.
Not Applicable.
Those in the petroleum industry are particularly concerned with extracting petroleum from the earth by boring holes from the earth surface down into deep underground rock formations that contain petroleum. To evaluate the geologic conditions and to facilitate and control the extraction process, various mechanical devices are placed into the borehole. Often, these downhole devices must be remotely controlled from the surface. Controlling the actions of these mechanical devices from the surface, according to the requirements of the evaluation and extraction processes, has been done in various ways including mechanical linkages, electrical signals transmitted through wires, fiberoptic link, electromagnetic signals through the earth, and signaling to the downhole devices by varying the fluid pressure in the borehole.
Complex control signals can readily be transmitted by electrical wire or fiberoptic link. However, in many cases it is inconvenient or impractical to provide these physical linkages from the surface to the devices deep in the borehole. Thus, other methods have been sought to transmit control signals to the downhole devices.
Electromagnetic communication through the earth between the surface and the borehole has been utilized by the mining and petroleum industries. However, this method is subject to limitations imposed by high-resistive rock formations and by deep boreholes. Electromagnetic wave signal strength is weakened as formation resistivity in the intervening earth increases. Electromagnetic noise may also prevent successful communication. Hardware in the wellbore such as casing strings and tubing may interfere with signal reception. Deep boreholes imply high temperature and high pressure conditions, as well as requiring longer signal transmission distances and are not amenable to the application of existing electromagnetic communication systems.
The method of signaling by fluid pressure variation has also been developed to remotely control downhole devices without the use of mechanical linkages or wires. For example, a downhole device may be equipped with a pressure sensor to detect the pressure of fluid occupying the borehole in the proximity of the sensor. To signal the downhole device, a surface operator raises and lowers the borehole fluid pressure in a predetermined sequence to signal the downhole device. A widely practiced use of fluid pressure variation to control a downhole device is exemplified by a tubing-conveyed perforating gun. The gun""s firing head is activated by raising fluid pressure in the borehole to a pre-determined level. This causes the shearing of a metal pin that initiates a chain of events resulting in firing of the gun.
However, this manipulation of borehole fluid pressure is time consuming, expensive, and sometimes hazardous. For example, for reliability the downhole device may require detection of a much higher than ambient borehole fluid pressure to initiate a certain action, such as 24000 psi as contrasted to 16000 psi ambient pressure in the proximity of the downhole device. Such high pressures induce significant stress to the downhole components. This stress, along with the stress of very high temperatures, risks the overstress of a downhole tool. In addition, the pressure at the wellhead may be raised to very high levels, such as 12000 psi. This high wellhead pressure is a safety concern as it places great stress on the constraining pipes and valves, once again risking overstress of these components. Another drawback of this method of device control is that only a very small range of command signals can be sent affordably due to the extremely low data transmission rate of the signaling method.
Current methods of controlling deep devices through pressure variation of the bore fluids are not completely reliable and the cost of occasional failure is very high. Removal of the failed device is time-consuming and costly and may also be hazardous to equipment and personnel. For example, it may cost over one million dollars to remove failed downhole components from deep wellbore. Moreover, these concerns promise to become more common in the future as deep wells become more prevalent and the deepest wells extend even deeper.
One downhole device in particular need of ideal remote control is the firing of a perforating gun. The use of electrical wires or fiberoptic conductors to communicate from the surface to these perforating guns is undesirable because of safety considerations and because of operational practicalities. In the case of tubing-conveyed perforating operations, in which the perforating gun becomes part of the permanent completion equipment of the well, no wires or cables can be tolerated in the wellbore. No alternative to activating the device through variations of borehole fluid pressure is presently available. Moreover, occasionally a perforating gun will have many fewer than all its explosive charges detonate. If, for example, only half the charges of a perforating gun detonate (and therefore the well produces only half the amount of hydrocarbons), the surface operator may believe that a well is much less productive than preliminary logging indicates. This problem is particularly acute in a very deep well where often the perforating gun is not, or cannot, be brought to the surface for inspection. The practice of abandoning the perforating gun in the wellbore after its activation is called for in the practice of permanent completion of the wellbore.
Thus there is a need in the petroleum extraction industry for a method that could overcome the deficiencies of currently available remote signaling systems. Ideally, such a method would be a safe new method of controlling downhole devices that does not require direct physical linkage by wire or fiberoptic. This method could provide a wide range of control commands and parameter settings, would be less costly in terms of total cost of the control process, would be swifter and would be very reliable. This ideal remote signaling method could also provide an indication of whether a command was received downhole for at least certain types of controllable devices.
A preferred embodiment of the invention is a seismic communication system suitable to communicate information to a device at an underground location, including a seismic source to transmit information by the generation of a series of seismic shots at selected times, a seismic receiver at the underground target to receive the series of seismic shots, and a processor in communication with the seismic receiver to decipher the information based on measurement of times, the times being based on the timing of a reference shot. The times may be measured by the cross-correlation of a first seismic shot with a second seismic shot, and translated by use of a project menu comparing the measured times to pre-selected instructions. A downhole clock may also have its clock drift accounted for by the measurement of these times.
One preferred underground device preferably includes a perforating gun with explosive charges that are detonated in response to the transmitted information. A set of one or more surface seismic receivers preferably can detect seismic waves created by the detonation of the underground explosive charges and determines about the proportion of explosive charges that detonated. The one or more seismic sources are also preferably at the surface.
The invention also may be viewed as a method of transmitting information to a location in a borehole, including the steps of generating a reference seismic signal, receiving the reference signal downhole, generating a second seismic signal, and receiving it at the underground location, and determining the information by the time of the second seismic signal. As previously, a perforating gun may be advantageously located in the borehole. A method to interpret a seismic signal includes receiving a first seismic signal at an underground location, waiting until a predetermined time according to an underground clock; listening for the presence of a second seismic signal at or about the predetermined time, and determining information based on the time of the second signal or a presence/absence of the second seismic signal. This information may be a coded command interpretable by reference to a stored project menu.